Corporate Presentation August 2013 Click to edit Master title style
2 ClickAbout to Forward edit Master Looking title style Statements
The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such statements may relate to, among other things, forecasted capital expenditures, drilling activity, completion of
acquisitions or reserves or future production attributable to them, development activities, timing of carbon dioxide (CO2) injections and initial production response in tertiary flooding projects, estimated costs, production rates and volumes or forecasts thereof, hydrocarbon
reserve quantities and values, CO2 reserves, helium reserves, potential reserves from tertiary operations, future hydrocarbon prices or assumptions, liquidity, cash flows, availability of capital, borrowing capacity, finding costs, rates of return, overall economics, net asset
values, estimates of potential or recoverable reserves and anticipated production growth rates in our CO2 models, or estimated production in 2013 and future production and expenditure estimates, and availability and cost of equipment and services. These forward-looking statements are generally accompanied by words such as “estimated”, “preliminary”, “projected”, “potential”, “anticipated”, “forecasted” or other words that convey the uncertainty of future events or outcomes. These statements are based on management’s current plans and assumptions and are subject to a number of risks and uncertainties as further outlined in our most recent Form 10-K and Form 10-Q filed with the SEC. Therefore, the actual results may differ materially from the expectations, estimates or assumptions expressed in or implied by any forward-looking statement made by or on behalf of the Company.
Cautionary Note to U.S. Investors – Current SEC rules regarding oil and gas reserve information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2012 were estimated by DeGolyer & MacNaughton, an independent petroleum engineering firm. In this presentation, we make reference to probable and possible reserves, some of which have been prepared by our independent engineers and some of which have been prepared by Denbury’s internal staff of engineers. In this presentation, we also refer to estimates of original oil in place, resource “potential” or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as probable and possible (2P and 3P reserves), include estimates of reserves that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.
3 ClickA Different to edit Kind Master of Oil title Company style
Proven • CO2 EOR is one of the most efficient tertiary oil recovery methods Process • 29% compound annual growth rate (CAGR) in our EOR production since 1999 • We have produced ~100 million barrels (gross) of oil from CO2 EOR to date
Unique • We acquire mature oil fields and recover oil using CO2 Strategy • Competitive advantage: strategic CO2 supply, over 1,100 miles of CO2 pipelines and a large inventory of mature oil fields Repeatable • We anticipate a decade of low teens annual EOR production growth Growth • Over 1 billion barrels of potential oil reserves
• We store CO2 captured from industrial facilities, resulting in net carbon reduction • By developing existing oil fields, we are disturbing fewer new habitats Value • Highest operating margins and capital efficiency in peer group Creation • Within the next 5 years, we anticipate a growing wedge of free cash flow
4 ClickDenbury to edit at aMaster Glance title style
Total 3P Reserves (12/31/12) ~1.1 BBOE % Oil Production (2Q13) 94% Total Daily Production – BOE/d (2Q13) 74,052
Proved PV-10 (12/31/12) $94.71 NYMEX Oil Price $9.9 billion Market Cap (6/30/13) $6.4 billion Total Net Debt (6/30/13)(1) $3.1 billion
CO2 Supply 3P Reserves (12/31/12) ~17 Tcf
CO2 Pipelines Operated or Controlled ~1,100 miles Credit Facility Availability (6/30/13) ~$1.3 billion
(1) Defined as long term debt and capital lease obligations, less current obligations, less cash and cash equivalents. As of 6/30/13, we had ~$260 million of borrowings outstanding under our $1.6 billion bank credit facility and our cash and cash equivalents totaled ~$76 million.
5 ClickWhat tois COedit2 EOR Master & How title Much style Oil Does It Recover?
Secure CO2 Supply Transport via Pipeline Inject into Oilfield
CO2 EOR Delivers Almost as Much Production as Primary and Secondary Recovery(1) Tertiary Recovery Remaining (CO2 EOR) Oil
~17%
Secondary Recovery (waterfloods) Primary ~18% Recovery
(1) Recovery of Original Oil in Place based on history at Little Creek Field. ~20%
6 Our Two CO EOR Target Areas: Click to edit2 Master title style Up to 10 Billion Barrels Recoverable with CO2 EOR
Denbury Rocky Mountain Region (2) 331 Million 3P CO2 EOR Barrels Estimated 1.3 to 3.2 Billion Barrels MT ND Recoverable in Rocky Mountain Region(1)
Greencore ID Pipeline SD Lost Cabin
WY
Existing Denbury CO Pipelines 2 Denbury Gulf Coast Region Denbury owned Fields With CO2 EOR Potential (2) 587 Million 3P CO2 EOR Barrels Existing or Proposed CO2 Source Owned or Contracted MS Other CO Sources Delta Pipeline Jackson 2 Dome Sonat MS Free State Pipeline Pipeline LA TX Green Pipeline
(1) Source: DOE 2005 and 2006 reports. (2) 3P tertiary oil reserve estimates based on year-end 12/31/12 SEC proved Estimated 3.4 to 7.5 reserves, based on a variety of recovery factors, includes CCA acquisition that Billion Barrels closed on 3/27/13. Recoverable in Gulf Coast Region(1)
7 CO2 EOR in Gulf Coast Region: Click to edit Master title style Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
(4) (4) Tinsley (1) Delhi Summary 46 MMBbls 36 MMBbls Tinsley Proved 201 Jackson Dome Potential 386 Delhi (2) Free State Pipeline Produced-to-Date 71 Davis Quitman (2) Heidelberg (3) Martinville Total MMBbls 658 Sandersville
Lake Sonat Summerland Soso Cypress Creek Eucutta St. John MS Pipeline Yellow Creek
Brookhaven Cranfield Houston Area(4) Mallalieu (4) Olive Conroe Citronelle Little Creek Hastings 60 - 80 MMBbls Smithdale 130 MMBbls McComb Webster 60 - 75 MMBbls Mature Area(4) Thompson 30 - 60 MMBbls 178 MMBbls Other 10 - 20 MMBbls Heidelberg(4) 160 - 235 MMBbls Green Pipeline 44 MMBbls Lockhart Crossing Conroe
Donaldsonville
Fig Ridge Webster Oyster Thompson Bayou
Hastings Cumulative Production 15 - 50 MMBoe Oyster Bayou(4) 50 – 100 MMBoe 20 - 30 MMBbls > 100 MMBoe Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Future CO2 Floods
Fields Owned by Others – CO2 EOR Candidates
(1) Proved tertiary oil reserves based on year-end 12/31/12 SEC proved reserves. Probable and possible tertiary reserve estimates as of 12/31/12, based on a variety of recovery factors. (2) Produced-to-Date is cumulative tertiary production through 12/31/12. (3) Using mid-points of range. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12.
8 CO2 EOR in Rocky Mountain Region: Click to edit Master title style Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage
CO2 Sources Cedar Creek Anticline Area (1) (1) Summary Existing or Proposed CO2 Source Existing CCA Fields 200 MMBbls Owned or Contracted CCA Acquisition(3) 60-80 MMBbls Proved --- DGC Beulah Other CO2 Sources 260 - 280 MMBbls Cedar Creek Potential 331 Anticline MONTANA Produced-to-Date --- (4) NORTH DAKOTA Total MMBbls 331 Bell Creek 30 MMBbls
Elk Basin Bell Creek First
CO2 EOR Production Bell Creek in 3Q13
LaBarge Area(2) Hartzog Draw(4) Greencore Pipeline 20 - 30 MMBbls 416 BCF Nat Gas 232 Miles Planned 12.7 BCF Helium Interconnect SOUTH DAKOTA (2013) 3.5 TCF CO2 Lost Cabin (COP) WYOMING Cumulative Production
Riley Ridge 15 - 50 MMBoe (DNR) 50 – 100 MMBoe > 100 MMBoe
(4) Denbury Owned Fields – Future CO2 Floods Shute Creek Grieve Field DKRW (XOM) Existing CO2 Fields Owned by Others – CO2 EOR Candidates Pipeline 6 MMBbls Pipelines (1) Probable and possible tertiary reserve estimates as of 12/31/12, using mid-point of ranges, based on a variety of recovery factors. Denbury Pipelines in Process (2) Proved reserves as of 12/31/12 and are presented on a gross working interest or 8/8ths basis, except those reserves Denbury Proposed Pipelines acquired from ExxonMobil in 4Q12 which are reported net to Denbury’s interest. Pipelines Owned by Others (3) Purchased from ConocoPhillips in a transaction that closed on 3/27/13. (4) Field reserves shown are estimated total potential tertiary reserves, including cumulative tertiary production through 12/31/12.
9 9 ClickMore to than edit a Master Billion titleBarrels style of Oil Potential
46 1,214 717 ...... 100% 89% 100% 100% Natural Oil Oil Oil Gas
462 409 451 ..... 77% 82% 80% Oil Oil Oil
(3) (1) (3)
(2)
(1) Based on year-end 12/31/12 SEC proved reserves. (2) Based on year-end 12/31/12 SEC proved reserves plus estimated 42 MMBOE for CCA acquisition that closed on 3/27/13.
(3) Estimates based on mid-point of internal estimates, refer to slide 3 for full disclosure of forward-looking statements. Pro-forma CO2 EOR potential includes 70 MMbbls from the CCA acquisition that closed on 3/27/13.
10 10 ProvenClick to Track edit MasterRecord title style
Net Daily Oil Production – Tertiary Operations (through 6/30/13) Mature Properties Tinsley Heidelberg Delhi Oyster Bayou Hastings
45,000
40,000
35,000
30,000
25,000 29% CAGR 20,000 (1999-2012)
15,000
10,000
5,000
- 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 1H13
11 11 ClickHighest to editOperating Master Margin title style in the Peer Group (1)
$/BOE 80 3-Months ended 3/31/2013 ~93% oil + high LLS exposure = Premium Pricing 70
60
50
40
30
20
10
0 DNR Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K
(1) Data derived from SEC filings, three months ended 3/31/13 and includes DNR, CLR, CXO, FST, NBL, NFX, PXD, RRC, SD SM, RRC, XEC. Calculated as revenues less lease operating expenses, marketing/transportation expenses, and production and ad valorem taxes. Includes historical data only, not adjusted for the CCA acquisition that closed on 3/27/13.
12 12 HighestClick to editCapital Master Efficiency title style in Peer Group(1)
(3)
TTM EBITDA(4) Efficiency Adj. F&D = Ratio
(1) Peer Group includes BRY,CLR,CXO,OAS,PXD,PXP,RRC,SD,SM,WLL. Includes historical data only, excludes impact of CCA acquisition that closed on 3/27/13. 13 (2) Three years ended 12/31/2012, and includes Encore Acquisition in 2010. Calculated as total capital expenditures divided by net reserve additions, including changes in future development costs and change in unevaluated properties.
(3) Includes 3-year average DD&A for CO2 properties of $0.82 per BOE (4) Trailing twelve months EBITDA ended 12/31/12.
13 13 ClickCO2 EORto edit – SuperiorMaster title Production style Profile
Projected Production Profile with Same Capital Spending Capital Spending per Year Based on EOR Spending Pattern
12,000 Year $MM Gulf Coast EOR Field 1 83 2 83 Bakken 3 60 10,000 4 60 5 68
6 52
8,000 7 52 8 52 9 45 6,000 Total $555
4,000
Production (Bbls/d) Production Production(BOEPD)
2,000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Years
Note: Assumes 700 BOEPD initial 30 day rate for Bakken wells.
14 14 ClickCO2 EOR to edit – Compelling Master title Economics style
WTI Breakeven Price for a 20% Before-Tax Rate of Return ($ per Bbl)(1)
(1) Source: KeyBanc as of March 2013. Defined as the threshold WTI oil price necessary to generate a 20% before-tax rate of return. Calculations reflect current type curve and basis differential of each play. Excludes acreage acquisition cost.
(2) Internal estimate for indicative large CO2 EOR development project in the Gulf Coast Region. Assumes a $5 basis premium. Excludes property acquisition cost.
15 15 COClick2 Supply to edit toMaster Support title Gulf style Coast Growth
1,800
Additional CO2 Potential (not reflected in graph) Probable & Possible Reserves: ~3 TCF 1,600 Improved Recovery of Proved Reserves: ~0.8 TCF Recycle: ~3 TCF ANTHROPOGENIC SUPPLY- Executed Agreements with Future Construction
1,400
1,200
JACKSON DOME 1,000 RISKED DRILLING PROGRAM
800
Volumes, MMCFPD Volumes,
2
600 CO
400 JACKSON DOME PROVED RESERVES ~6.1 TCF Estimated as of 12/31/2012 200
0 2010 2012 2014 2016 2018 2020 2022 Note: Forecast based on internal management estimates and includes fields currently owned. Actual results may vary.
16 ClickGulf Coast to edit Industrial Master title Partners style
Currently Producing or Under Construction Air Products PCS Nitrogen Mississippi Power – (Under Construction) • Port Arthur, Texas • Geismar, Louisiana • Kemper County, MS • Hydrogen Plant • Ammonia Products • Gasifier • Capture Date: 1Q 2013 • Capture Date: 2Q 2013 • Capture Date: ~2014 • Quantity: ~50 MMcf/d • Quantity: ~20 MMcf/d • Quantity: ~115 MMcf/d Future Construction (currently planned or proposed) Lake Charles Cogeneration Ammonia Plant Chemical Plant • Lake Charles, Louisiana • Near Green Pipeline • Near Green Pipeline • Petroleum Coke to • Capture Date: ~1Q 2016 • Capture Date: ~2020 Methanol Plant • Quantity: ~85 MMcf/d • Quantity: ~200 MMcf/d • Capture Date: ~2018 • Quantity: >200 MMcf/d
17 17 ClickCO2 Supply to edit toMaster Support title Rocky style Mountain Growth
LaBarge Area ● Estimated Field Size: 750 Square Miles
● Estimated 100 TCF of CO2 Recoverable
Riley Ridge – Denbury Operated ● 100% WI in 9,700 acre Riley Ridge Federal Unit ● 33% WI in ~28,000 acre Horseshoe Unit
● Estimated 2.2 TCF CO2 proved reserves
Shute Creek – XOM Operated (1) ● Denbury acquired 1/3 of XOM’s CO2 reserves in 4Q12 LaBarge Area ● Based on XOM’s current plant capacity and 416 BCF Nat Gas availability, Denbury could receive up to ~115 MMcf/d 12.7 BCF Helium 3.5 TCF CO2 of CO2 from the plant
● Estimated 1.3 TCF CO2 proved reserves
Composition of Produced Gas Stream:
~65% CO2; ~20% Natural Gas; ~5% Hydrogen Sulfide; <1% Helium, and other gasses
1) Proved reserves as of 12/31/12 and are presented on a gross working interest or 8/8ths basis, except those reserves acquired from ExxonMobil in 4Q12 which are reported net to Denbury’s interest.
18 18 ClickStrong to editFinancial Master Position title style
● ~$1.3 billion availability under Debt to Capitalization credit facility on 6/30/13 (6/30/13)
38% Debt
Unused Credit 83% Facility
$1.6 billion borrowing base + (6/30/13) Cash ~ $76 million
19 19 Click2013 toSummary edit Master Guidance title style(1)
2013 Capital Budget – $1.06 Billion(2) 2013 Production Estimate
2012 2013E 2013E All Other Operating area $170 MM (BOE/d) (BOE/d) Growth Tertiary Floods 36,500 - $580MM Tertiary Oil Fields 35,206 4-12% CO2 Sources 39,500 $200MM Cedar Creek Anticline(3) 8,503 16,200 CO2 Pipelines $110MM Non-Tertiary Oil Fields 13,133 16,000
68,700 - Total Estimated Production 56,842 21-26% 71,700
~$224 million remain under current stock repurchase authorization. Stock re-purchased to date increases production per share ~9%(4) We now expect tertiary and total production to average near the high end of their respective ranges.
We estimate the 2013 capital program(5) to be fully funded at low $90’s NYMEX WTI crude oil price.
(1) See slide 3 for full disclosure of forward-looking statements. (2) Excludes capital costs on G&G costs; internal acquisition, exploration and development costs; interest; and pre-production start-up costs associated with new tertiary fields, estimated at $160 million. (3) Includes impact of CCA acquisition that closed on 3/27/13. See slide 33 for more details. (4) Through 6/30/13, total stock purchased since October 2011 is nearly 36 million shares at an average cost of just over $15 per share. (5) Including capital costs on G&G costs; internal acquisition, exploration and development costs; interest; and pre-production start-up costs associated with new tertiary fields, estimated at $160 million.
20 20 ClickHedges to editProtect Master Against title Downside style in Near-Term(1)
Crude Oil (2) 2013 2014 2015
3rd 4th 1st 2nd 1st Half 2nd Half Quarter Quarter Quarter Quarter
Volumes hedged (Bbls/d) 56,000 54,000 58,000 58,000 58,000 58,000
Principal price floors ~$80 $80 $80 $80 ~$82 ~$82
Principal price ceilings(3) ~$109 ~$118 ~$102 ~$98 ~$99 ~$97
(1) Figures and averages as of 7/15/13. (2) Crude oil derivative contracts are based on West Texas Intermediate (WTI) NYMEX and Argus LLS price basis. See slide 45 for details. (3) Averages are volume weighted.
21 21 (1) ClickA Decade to edit of Master CO2 EOR title Production style Growth
Anticipating Average Annual Percentage Growth Rate in the Low Teens
100,000 Expected Peak
CO2 EOR Cap-Ex
35,206
● Bell Creek ● Hartzog Draw ● Cedar Creek Anticline ● Webster ● Conroe ● Thompson
(1) 2013 and future forecasted capital expenditures and production may differ materially from actual results. Does not include recently completed incremental CCA acquisition. See slide 3 for full disclosure of forward-looking statements.
22 22 ClickCO2 EORto edit – ProvenMaster titleFree style Cash Flow Generator
+/- $1.7 Billion
First Year of Free Cash Flow
(1) Calculated from actual historical operating cash flow (revenues less operating expenses) less capital expenditures and currently projected operating income and capital expenditures in 2013 and beyond using a flat $90 NYMEX crude oil price. Includes Jackson Dome and Pipeline expenditures in Gulf Coast. See slide 3 for full disclosure of forward-looking statements.
23 23
ClickEstimated to edit CO Master2 EOR title Peak style Production Rates
Estimated Peak Production Rate Produced Proved Potential First Expected Operating Area (Net MBOE/d) to date(1) Remaining(1) Remaining(2) Production Peak Year < 5 5-10 10-15 15-20 > 20 (MMBOE) (MMBOE) (MMBOE) Mature Area 1999 2010 54 54 70 Tinsley 2008 2012-14 9 28 9 Heidelberg 2009 2018-20 3 35 6 Delhi 2010 2015-17 3 25 8 Oyster Bayou 2012 2015-17 <1 14 11 Hastings 2012 2018-20 1 45 24 Bell Creek 2013 2019-21 ------30 Webster 2015 2022-25 ------68 Hartzog Draw 2016 2021-23 ------25 Conroe 2017 2033-35 ------130 Cedar Creek Anticline(3) 2017 2023-27(3) ------200(3) Thompson 2019 2025-27 ------45
Expected year of first tertiary production.
(1) Tertiary oil production and reserves as of 12/31/2012 (2) Based on internal estimates of reserve recovery, using mid-points of ranges. (3) Does not include impact of CCA acquisition that closed on 3/27/13. Potential tertiary reserves for CCA acquisition are currently estimated at 60-80 MMBOE.
24 24 ClickIN SUMMARY: to edit Master A Different title style Kind of Oil Company
Leading CO2 Enhanced Oil Recovery Company in the U.S. with a Unique Profile
• Significant strategic advantage in CO2 EOR
• Well defined and focused long-term growth strategy
• Highest operating margin and capital efficiency in peer group
• Substantial free cash flow generation from CO2 EOR after up- front investment in infrastructure
25 25 ClickCorporate to edit Information Master title style
Corporate Headquarters Denbury Resources Inc. 5320 Legacy Drive Plano, Texas 75024 Ph: (972) 673-2000 Fax: (972) 673-2150 denbury.com
Contact Information Phil Rykhoek President & CEO (972) 673-2000
Mark Allen Senior VP & CFO (972) 673-2000
Jack Collins Executive Director, Investor Relations (972) 673-2028 [email protected]
Ernesto Alegria Manager, Investor Relations (972) 673-2594 [email protected]
26 26 Appendix ClickWhy tois editCO2 MasterEOR our title core style focus?
● High Confidence of Oil Target . ~100 million barrels (gross) produced by Denbury to date . Net upward adjustments to reserves-to-date
● CO2 Flooding Recovers Oil (CO2 ♥’s Crude Oil)
. First commercial CO2 EOR flood started production in 1972 . Over 1.5 billion barrels produced to date in the US(1) . Current estimated production in the US is >280 MBbls/d(2) ● A Very Repeatable Process with a lot of Running Room
. Up to 10 Billion Barrels Recoverable with CO2 EOR in our two operating areas
. Over 900 Million Barrels (net) of CO2 EOR potential in our portfolio today
(1) Oil & Gas Journal, Dec. 7, 2009 (2) Oil & Gas Journal, July 2, 2012
28 28 ClickCO2 EORto edit is Mastera Proven title Process style
Significant CO2 EOR Operators by Region Significant CO2 Suppliers by Region Gulf Coast Region Gulf Coast Region • Denbury Resources • Jackson Dome, MS (Denbury Resources) Permian Basin Region Permian Basin Region • Occidental • Kinder Morgan • Bravo Dome, NM (Kinder Morgan, Occidental) • McElmo Dome, CO (ExxonMobil, Kinder Morgan) • Whiting • Sheep Mountain, CO (ExxonMobil, Occidental) Rockies Region Rockies Region • Denbury Resources • Anadarko • Riley Ridge, WY (Denbury Resources) Canada • LaBarge, WY (ExxonMobil, Denbury Resources) • Lost Cabin, WY (ConocoPhillips) • Cenovus • Apache Canada • Dakota Gasification – Anthropogenic (Cenovus, Apache)
300 CO2 EOR Oil Production by Region
Gulf Coast/Other 250 DGC Mid-Continent Lost Riley Ridge Cabin 200 Rocky Mountains & LaBarge /d Permian Basin 150 McElmo Dome Bravo Dome MBbls 100 Jackson Dome 50 Significant CO2 Source
- 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
29 29
ClickCO2 Operations:to edit Master Oil title Recovery style Process
CO2 PIPELINE - from Jackson Dome INJECTION WELL - Injects
CO2 in dense phase
PRODUCTION WELLS Produce oil, water and CO Oil Formation 2 (CO2 is recycled)
CO2 moves through formation mixing with oil droplets, expanding them and Model for Oil Recovery Using CO2 is +/- 17% moving them to of Original Oil in Place (Based on Little Creek) producing wells. Primary recovery = +/- 20% Secondary recovery (waterfloods) = +/- 18%
Tertiary (CO2) = +/- 17%
30 30 ClickCO2 EORto edit – ProvenMaster titleValue style Creation
Investments – Inception-to-12/31/2012 ($) Billions Gulf Coast EOR Fields $3.0
Gulf Coast CO2 Sources & Pipelines 2.0 Less Undeveloped: EOR Fields 0.1
CO2 Pipelines 0.2 (0.3) Net Investment-to-Date – Proved Properties 4.7
Inception-to-Date Net Revenues 4.1 Net Cash flow (0.6) PV10 of proved EOR at 12/31/2012 6.8 Value Created $6.2
31 31 ClickStrategic to edit and Master Value-Driven title style M&A Transactions
Divestitures
Est. Est. Proved Impact on Est. Potential Est. Proved Production(1) Reserves Est. PDP Current Reserves(2) PV10(3) Assets (Quarter close date) (BOE/d) (MMBOE) % FCF(4) (MMBOE) ($Billions)
Non-Core LA & MS (1Q12) 1,400 6 54% + --- 0.2
Non-Operated Greater Aneth (2Q12) 650 6 58% + --- 0.1
Bakken (4Q12) 15,850 109 30% – 191 1.5 Total Sold 17,900 121 33% 191 1.8 Acquisitions Est. Est. Proved Impact on Est. Potential Est. Proved Production(1) Reserves Est. PDP Current Reserves(2) PV10(3) Assets (Quarter close date) (BOE/d) (MMBOE) % FCF(4) (MMBOE) ($Billions)
Thompson Field (2Q12) 2,200 17 34% + 45 0.5
Webster Field (4Q12) 1,000 4 100% + 68 0.1
Hartzog Draw (4Q12) 2,600 5 100% + 25 0.1
COP CCA Assets (1Q13) 11,000 42 91% + 70 1.1
Total Purchased 16,800 68 78% 208 1.8
Cash + 0.1 + Additional CO2 Supply in the Rockies: Received Purchase XOM LaBarge CO2 (4Q12) Up to 115 MMcf/d Production 1.3 TCF Proved Reserves at 12/31/2012 Price + 0.3 Total (1) Est. production at time of acquisition or divestiture; Bakken area production is actual year-to-date average production through 9/30/12. Value: $2.2 (2) Preliminary mid-point of estimates based on internal calculations. Potential reserves include probable and possible reserves. (3) Estimated discounted net present value of proved reserves or impact of sales on net present value, using a 10% annual discount rate. (4) Spent $90 million in excess of operating cash flow on Bakken area assets in first nine months of 2012; expect capital expenditures on acquired properties to be minimal.
32 32 ClickAcquisition to edit Masterof Cedar title Creek style Anticline Fields
Transaction Terms
Glendive North ● $989 million cash, after working capital adjustments Glendive Gas City
● Acquisition closed on 3/27/13 with a 1/1/13 effective date DAWSON MONTANA
WIBAUX DAKOTA NORTH ● The original oil in place of all units in the CCA is estimated North Pine PRAIRIE at over three billion barrels of oil South Pine
Including this acquisition, we estimate that a CO flood of GOLDEN ● 2 Cabin Creek VALLEY our CCA assets could recover between 260-280 million Monarch SLOPE barrels of oil East Lookout Pennel ● At the time of acquisition, daily production was ~11,000 Butte FALLON Cedar Hills Coral Creek barrels of oil equivalent per day (~95% oil, ~4% NGLs) South Unit ● We estimate the acquired properties to add ~7,700 BOE/d Little Beaver to our 2013 production estimates Existing CCA Properties BOWMAN ● Conventional (non-tertiary) reserves ~42 million BOE CCA Acquisition CCA Fields Owned by Others
33 33 ClickDenbury to edit vs. Master Peer Group title style Trading Multiples
16
14
12
10
8 P/CFPS
6 Median Denbury 4
2
- 0% 50% 100% 150% 200% 250% 300% 350% 400% P/NAV
Source: KeyBanc report dated 7/29/13 – Net Asset Values (NAVs) based on YE12 proved reserves and KeyBanc price deck with balance sheet adjustments to reflect latest 10Q. Peer Group includes CLR, CXO, NFX, PXD, RRC, SD, SM, WLL, XEC
34 34
ClickCO2 EORto edit Generalized Master title Type style Curve
Plateau
Production Rate Production
Incline (Yrs) Plateau (Yrs) Decline (Yrs)
Large Fields 6 6.5 30
Average Fields 4.5 5.5 25
Small Fields 4 5 20
35 35
ClickTexas to CO edit2 Pipeline Master Infrastructure title style – Economies of Scale
Hastings Oyster Bayou Webster Conroe Thompson $14
$12 70
MMBbls
$10 95 $8 MMBbls
$6 163 $4 MMBbls
Pipeline cost per tertiary Pipeline cost tertiary per Bbl 293 MMBbls 338 $2 MMBbls
$- Hastings + Oyster Bayou + Webster + Conroe + Thompson
(1) Using mid-point of ranges and includes costs of Green Pipeline plus forecasted costs for required incremental pipelines to each field.
36 36 ClickEncore to editAcquisition Master title was style Highly Profitable
Purchase price: (Billions) Equity $2.8 Debt assumed 1.0 Total value $3.8 (1)
Value: (Estimated values at $94.71/Bbl – 12/31/12 SEC Pricing) Proved reserves at 12/31/12 $1.5 (2)
Value received from sold properties ~3.6 (3)
Net cash flow from 3/9/10 to 9/30/12 0.4 Total ~$5.5 Additional potential:
(4) CO2 EOR potential 230 MMBOE
(1) Excludes consolidated ENP debt and minority interest in ENP. (2) Excludes sold properties, and ENP reserves. (3) Includes ~$2 billion of estimated value of Bakken sale.
(4) Made up of CO2 EOR potential at Bell Creek and CCA acquired from Encore.
37 37
ClickCapital to editSpending Master Range title style for CO2 Floods
100
90
80
70
60
50
40
30
% of Total Capital of Total % 20
10
0 1 2 3 4 5 Year
38 CapitalClick Spendingto edit MasterFlexibility title in Low style Oil Price Environment
Unique characteristics of CO2 EOR provides significant capital flexibility
• We attempt to balance development expenditures with free cash flow • In contrast to shale plays, a reduction in EOR capital spending will not immediately impact EOR production growth
• Our newer EOR projects have many years of production growth with fairly low capital expenditures
• It is relatively easy to slow the development pace of EOR projects - most Rocky Mountain EOR infrastructure development could be delayed if necessary
• No lease expiration issues and limited capital commitments on EOR projects • We can hold production flat over the next several years using 50% or less of our 2013 forecasted capital expenditures
39 39 ClickProduction to edit Masterby Area title (BOE/d) style(1)
Operating area 2Q12 3Q12 4Q12 2012 1Q13 2Q13 2013E
Tertiary Oil Fields 35,208 34,786 37,550 35,206 39,057 38,752 36,500 – 39,500
Cedar Creek Anticline 8,535 8,490 8,493 8,503 8,745 19,935 16,200 (2)
Other Rockies Non-Tertiary 3,060 3,037 3,616 3,231 5,163 4,958 5,400
Texas Non-Tertiary 4,573 5,173 5,513 4,737 6,692 6,932 6,300
Other Gulf Coast Non-Tertiary 5,401 4,538 4,880 5,165 4,166 3,475 4,300
Total Continuing Production 56,777 56,024 60,052 56,842 63,823 74,052 68,700 – 71,700
Bakken Area 15,503 16,752 10,064 14,395 ------~94% Oil
Gulf Coast Non-Core Properties ------262 ------
Paradox Basin Properties 57 ------190 ------
Total Production 72,337 72,776 70,116 71,689 63,823 74,052
(1) See slide 3 for full disclosure of forward-looking statements. (2) Includes impact of CCA acquisition that closed on 3/27/13.
40 40 ClickTertiary to edit Production Master title by Fieldstyle
Average Daily Production (BOE/d) Field 2009 2010 2011 2012 4Q12 1Q13 2Q13 Brookhaven 3,416 3,429 3,255 2,692 2,520 2,305 2,339 Little Creek Area 1,502 1,805 1,561 1,091 999 1,002 906 Mallalieu Area 4,107 3,377 2,693 2,338 2,127 2,116 2,157 McComb Area 2,391 2,342 1,997 1,785 1,722 1,685 1,610 Lockhart Crossing 804 1,397 1,465 1,176 1,072 1,134 1,020 Martinville 877 720 462 507 522 480 424 Eucutta 3,985 3,495 3,121 2,868 2,730 2,636 2,642 Soso 2,834 3,065 2,347 1,989 2,021 2,110 2,016 Cranfield 448 911 1,123 1,159 1,269 1,389 1,257 Mature Area 20,364 20,541 18,024 15,605 14,982 14,857 14,371
Tinsley 3,328 5,584 6,743 7,947 8,166 8,222 8,225
Heidelberg 651 2,454 3,448 3,763 3,930 3,943 4,149
Delhi --- 483 2,739 4,315 5,237 5,827 5,479
Hastings ------2,188 3,409 3,956 4,010
Oyster Bayou ------5 1,388 1,826 2,252 2,518
Total Tertiary Production 24,343 29,062 30,959 35,206 37,550 39,057 38,752
41 41 ClickAnalysis to edit of MasterTertiary title Operating style Costs
(1) Correlation 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 w/Oil $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE $/BOE
CO2 Costs Direct $5.39 $5.43 $4.87 $4.53 $5.76 $5.14 $4.96 $5.21 $6.78 $6.13
Power & Fuel Partially 6.12 6.16 6.24 6.71 6.71 6.69 6.69 5.98 6.47 6.85
Labor & Overhead None 3.94 3.77 3.85 3.90 4.59 4.64 4.74 4.57 4.43 4.56
Repairs & Maintenance None 1.11 1.34 1.86 1.22 1.74 1.29 1.50 1.21 1.15 0.72
Chemicals Partially 1.62 1.44 1.80 1.67 1.63 1.27 1.46 1.59 1.65 1.57
Workovers Partially 3.75 2.53 3.44 2.67 3.42 3.01 3.68 3.30 2.94 3.60
Other None 3.00 2.20 2.85 2.89 2.89 0.91 0.47 0.73 1.29 0.09
Total $24.93 $22.87 $24.91 $23.59 $26.74 $22.95 $23.50 $22.59 $24.70 $23.52 (1)
NYMEX Oil Price $94.26 $102.58 $89.60 $93.93 $102.89 $93.49 $92.29 $88.18 $94.42 $94.14
Realized Tertiary Oil Price $98.59 $112.27 $104.44 $113.37 $112.68 $107.10 $102.90 $103.75 $110.24 $105.38
(1) Does not include effect from Delhi contingency, $70 million or $19.85 per BOE
42 42 ClickNYMEX to edit Differential Master title Summary style
Crude Oil Differentials 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13
Tertiary Oil Fields $4.33 $9.69 $14.84 $19.44 $9.80 $13.60 $10.61 $15.57 $15.82 $11.23
Mississippi (4.50) 1.32 7.25 6.98 2.44 8.63 2.48 10.82 11.28 8.02
Texas (4.29) (3.46) 1.19 12.29 1.77 5.38 5.46 13.10 12.57 6.86
Cedar Creek Anticline (3.27) 1.25 0.85 (0.29) (9.89) (7.44) (9.26) (0.23) (2.65) (6.44)
Other Rockies(1) (12.04) (6.25) (6.25) (8.11) (16.30) (16.67) (14.42) (6.57) (8.71) (8.53)
Denbury Totals ($0.59) $3.72 $7.25 $9.14 ($0.37) $2.14 $0.80 $9.43 $11.17 $4.78
(1) Excludes Bakken Area assets sold
43 43 ClickTracking to edit Oil Master Prices title style
● We currently sell ~44% of our oil production based on LLS index price and ~22%(1) at prices partially tied to the LLS index price, most of which have also improved relative to WTI, but to a lesser degree
$135 Light Louisiana Sweet $125
Brent $115
$105
$95 WTI NYMEX $85
$75
(1) Does include production from recent CCA acquisition
44 44 ClickCrude to Oil edit Hedge Master Detail title(1) style
2013 Crude Oil Hedges (BOPD) 2015 Crude Oil Hedges (BOPD)
(2) Average Ceiling Average(2) Ceiling Instrument Volume Basis Floor Ceiling Low High Instrument Volume Basis Floor Ceiling Low High
Q3 Collars 4,000 WTI 75.00 126.80 120.50 133.10 Q1 Collars 29,000 WTI 80.00 95.84 95.00 96.70 12,000 WTI 80.00 105.58 104.50 106.50 9,000 WTI 80.00 100.59 100.50 100.90 40,000 WTI 80.00 108.46 108.00 109.60 10,000 LLS 85.00 100.30 100.00 101.50
10,000 LLS 85.00 102.59 102.00 104.00 Q4 Collars 16,000 WTI 80.00 103.39 102.25 105.00
20,000 WTI 80.00 120.66 120.00 121.50
18,000 WTI 80.00 126.63 126.00 127.50 Q2 Collars 10,000 WTI 80.00 93.50 93.50 93.50
28,000 WTI 80.00 95.02 95.00 95.25 2014 Crude Oil Hedges (BOPD) 12,000 LLS 85.00 101.50 101.00 102.00 Average(2) Ceiling 8,000 LLS 85.00 102.76 102.50 103.00 Instrument Volume Basis Floor Ceiling Low High
1H Collars 12,000 WTI 80.00 98.23 96.55 100.00
16,000 WTI 80.00 102.43 101.60 102.70
24,000 WTI 80.00 103.32 103.00 103.90
6,000 WTI 80.00 104.23 104.10 104.50
2H Collars 20,000 WTI 80.00 96.77 96.55 96.90
16,000 WTI 80.00 97.36 97.00 97.75
22,000 WTI 80.00 98.87 98.40 100.00 (1) Figures and averages as of 7/15/13 (2) Averages are volume weighted
45 45 ClickActual to Industryedit Master Recovery title style Curves
Range of Recovery 10%-18%
46 46 ClickActual to Curvesedit Master – Denbury title style Mature Fields
Range of Recovery 11%-20+%
47 47 ClickStrong to editFinancial Master Position title style
($MM) 3/31/13 6/30/13 Cash and cash equivalents $62 $76 Bank credit facility (Borrowing base of $1.6 billion, matures May 2016) 275 260 9.50% Sr. Sub Notes due 2016 (Callable May 2013 at 104.75% of par) 40 -- 8.25% Sr. Sub Notes due 2020 (Callable February 2015 at 104.125% of par) 996 996 6.375% Sr. Sub Notes due 2021 (Callable August 2016 at 103.188% of par) 400 400 4.625% Sr. Sub Notes due 2023 (Callable January 2018 at 102.313% of par) 1,200 1,200 Other Encore Sr. Sub Notes 4 4 Genesis pipeline financings / other capital leases 347 339 Total long-term debt(1) $3,262 $3,199 Equity 5,146 5,271 Total capitalization $8,408 $8,470
Annualized Adjusted cash flow from operations(2) $1,263 $1,236 Net Debt to Annualized Adjusted cash flow from operations(2)(3) 2.5x 2.5x Net Debt to Annualized EBITDA(2)(3) 2.3x 2.4x Net Debt to total capitalization 38% 37%
(1) Excludes current portion of capital lease obligations and pipeline financings totaling approximately $34.0 million on 3/31/13 and $34.1 million on 6/30/13, respectively . (2) A non-GAAP measure; please visit our website for a full reconciliation. Represents historical amounts not adjusted for recent CCA acquisition, which closed on 3/27/13. (3) Net debt defined as long-term debt and capital lease obligations, less current obligations, less cash and cash equivalents.
48 48